The huge Cirata reservoir, commonly known as Waduk Cirata, located in West Java is the home of two big green energy power plants in Indonesia – the newly commissioned 192 MWp solar plant and the 1000 MW hydro power plant.
The 6200-hectare (62 Km2) reservoir is located along the River Citarum.
Based on geological surveys that began in 1922 along the River Citarum and further surveys conducted by Dutchman W. J. van Blommestien, in 1948 he identified the Cirata area as a potential site for constructing a reservoir and a hydropower plant.
The Cirata Hydro Power Plant
It was not until 1981 that Indonesia decided to construct a hydropower plant in Cirata.
To make way for the construction of the Cirata reservoir, 6335 families located in 20 villages were relocated.
The main dam of the Cirata reservoir was completed on 1 September 1987.
Initially, the MW Cirata hydropower plant was completed with 250 MW capacity in early 1988.
Its capacity was increased to 500 MW later in the same year, 750 MW in 1997, and finally 1000 MW in 1998, making it the biggest hydropower plant in Indonesia.
The Floating Cirata Solar Farm
President Joko Widodo of Indonesia inaugurated the huge floating Cirata solar farm on November 9, 2023.
The 192 megawatt peak (MWp) Cirata solar plant, the largest floating solar plant in Southeast Asia is located in Cirata reservoir in West Java. The project is a collaboration between Masdar of UAE and Indonesia’s national power company, PLN.
The solar farm, comprised of 13 clusters, is powered by 340,000 solar panels capable of supplying 768 Mwh/day of electricity to 50,000 houses. The green power plant reduces 214,000 tons of CO2 emission per year.
Currently occupying only 4% of the reservoir surface area, the plant capacity may be increased to 1000 MWp in the future.
Epilogue
Today, with the newly completed solar farm, Waduk Cirata is indeed a magnificent site to behold.
It is also a significant site as it is home to two big green energy power plants.
This article is adapted from various sources by Jamin Djuang, Chief Learning Officer of LDI Training.
Dr. Larry W. Lake of The University of Texas at Austin will present the following webinar on CO2 EOR and CCUS.
Webinar title: From CO2-EOR to CCUS
Presenter: Dr. Larry W. Lake of The University of Texas at Austin
Date: January 19, 2024
Time: 9 AM – 10 AM Texas time (UTC-6)
In this webinar, Dr. Larry Lake will discuss the following aspects of CO2, from EOR to CCUS:
Properties of CO2
Basis for CO2-EOR
Transition from CO2-EOR
Review of CCS field projects.
Dr. Lake will answer questions after the presentation.
About Dr. Larry W. Lake
Dr. Larry W. Lake is a professor in the Hildebrand Department of Petroleum and Geosystems Engineering at The University of Texas at Austin where he holds the Shahid and Sharon Ullah Chair.
He holds BSE and PhD degrees in Chemical Engineering from Arizona State University and Rice University, respectively.
He is the author or co-author of more than 150 technical papers, four textbooks, and the editor of three bound volumes.
Dr. Lake has served on the Board of Directors for the Society of Petroleum Engineers (SPE) and received the SPE/DOE IOR Pioneer Award in 2000.
He won the 1996 Anthony F. Lucas Gold Medal of the AIME, the Degolyer Distinguished Service Award in 2002, and has been a member of the US National Academy of Engineers since 1997.
Larry Lake was named a Distinguished Graduate of UT in 2022. He has been at the University of Texas since 1978.
Dr. Larry W. Lake is a professor in the Hildebrand Department of Petroleum and Geosystems Engineering at The University of Texas at Austin where he holds the Shahid and Sharon Ullah Chair.
Larry Lake holds BSE and PhD degrees in Chemical Engineering from Arizona State University and Rice University, respectively.
He is the author or co-author of more than 150 technical papers, four textbooks and the editor of three bound volumes.
Dr. Lake has served on the Board of Directors for the Society of Petroleum Engineers (SPE) and received the SPE/DOE IOR Pioneer Award in 2000.
He won the 1996 Anthony F. Lucas Gold Medal of the AIME, the Degoyer Distinguished Service Award in 2002, and has been a member of the US National Academy of Engineers since 1997.
Larry Lake was named a Distinguished Graduate of UT in 2022. He has been at the University of Texas since 1978.
A large new volume of LNG, up to 14.5 million tonnes per year, will increase the total supply of LNG in Indonesia between now and 2030. The new LNG volume will come from the following LNG production centers:
Tangguh LNG Train #3 – 3.8 MPTA in the Q4 2023.
Genting Kasuri FLNG – 1.2 MTPA in 2026
Masela Abadi LNG – 9.5 MTPA in 2029
This article looks at the new LNG production capacity between now and 2030, and how the domestic market can absorb this new LNG volume.
The objective of this market analysis is to give information and incentives to both the LNG producers and buyers – domestic and international – to start planning on how to take advantage of the new LNG volume.
Assumptions and Scenario
First, here are the numbers and scenarios used in this market analysis.
On the domestic demand side, only Jawa 1 Power is the confirmed new power demand.
The development of small-scale LNG receiving terminals is considered less likely to happen.
There will be new LNG demands from the smelters located in Bahodopi and Sumbawa.
Another potential LNG domestic consumption should come from Pertamina’s refinery fuel conversion, which will come by the end of this decade.
Due to the high prices of Indonesia’s LNG as they are indexed to oil prices, the fertilizer and downstream industries are expected to play a very minor role in the domestic LNG market.
Results of Analysis
The results of the market analysis are presented in the graphic shown in this article.
The graphic shows that once full production of LNG from the Masela Abadi plant starts in 2030, the domestic-allocated LNG volume will far exceed the domestic LNG demand.
The surplus between the domestic-allocated LNG volume and the domestic demand in 2030 amounts to around 4.3 MPTA. To put it in perspective, this amount of gas is good enough to feed a 5-GW gas-fired power plant.
Without additional infrastructures or new domestic demand for LNG in the future, the producers will have to sell it together with the export-oriented volume of around 6.5 MTPA to the international markets.
Recommendations
There will be a big surplus of LNG to meet the domestic demand in 2030. Nevertheless, the outlook for LNG is good for exports.
To increase domestic demand for LNG, new infrastructures are needed to distribute the gas.
To make LNG more absorbable to domestic markets, the LNG pricing mechanism will need to be adjusted.
Barium sulfate (BaSO4) is one type of scale that is extremely difficult to remove. It is frequently removed mechanically, with higher chances of ending up cutting or replacing the scaled part of the system.
Many BaSO4 dissolvers that can remove BaSO4 effectively are available, with the only barrier is the cost of these chemicals (especially when huge amounts are necessary).
A good alternative is the chelating agents. Polyaminocarboxyates (PAC) such as EDTA, DTPA, CDTA, and NTA have been successfully used as BaSO4 dissolvers as they are considered:
-Cheap
-Non-corrosive
-Easy to handle
– Easy to formulate and improve
Some tips to effectively remove BaSO4 using PAC at a cheap price:
■ Determine the scale deposit’s full composition, layer-wise composition is recommended.
■ DTPA is considered the most effective PAC in dissolving BaSO4, but it is more expensive than the others. So, lab dissolution studies should be conducted with various PACs since EDTA or CDTA might be enough to do the job at a cheaper price.
■ Conduct laboratory dissolution studies to determine: effective concentration, use of catalysts, best temperature, soaking time, and side effects if any.
■ Various catalysts can be used to boost PAC performance such as oxalate, thiosulfate, glycolate, maleate, succinate, and even phosphonate.
■ pH has to be >10, between 10 and 11.5, to get the best performance of PACs.
■ High temperature is recommended (> 60 OC).
■ Long soaking time is necessary. It might take days to dissolve the thick dense BaSO4 scale layer. The amorphous scale will be done in a shorter time. So, buckle up and be patient.
■ Start the cleaning with organic solvent flushing, to remove the oil film or organic deposits that might be covering the BaSO4 scale.
■ If scale analysis showed acid soluble components, you can perform inhibited acid flushing to dissolve these components. This step will make the scale layer amorphous and decrease its strength especially if these acid-soluble components are like cementing materials. A water flush might be necessary after acid flush to avoid acid residue interactions with high pH PACs main treatment.
■ Soak the dissolver for the predetermined time. But don’t give up if the first soak wasn’t that efficient, a second or maybe third soaking might be necessary. It is not magic, it’s a process.
■ Agitation or circulation is recommended if possible.
■ Mechanical aids help a lot in improving dissolution efficiency.
This article is contributed by Abdullah Hussein, author of “Essentials of Flow Assurance Solids in Oil and Gas Operations”.
The energy transition is a pathway to achieve net zero by transforming the energy sector into one that is low-carbon while maintaining energy sustainability and security—increasing and utilizing the demand for oil and gas throughout the transition while reducing greenhouse gas emissions.
Challenges of the Oil and Gas Industry in Energy Transition
The oil and gas industry is facing challenges to produce energy economically and sustainably as policymakers seek emissions reductions through carbon pricing and trading. According to the International Energy Agency (IEA), the transition of oil and gas should consider three main focus levers:
♦ Rising demand for energy due to a growing global population
♦ Affordable and reliable supplies of liquid and gas, since the industry plays a critical role in economic systems
♦ Reducing the energy emissions contribution in line with the decarbonization movement to achieve net-zero emissions.
Recommendations for the Oil and Gas Industry
According to the Atlantic Council Global Energy Center, recommended steps to support and lead the transition movement in the oil and gas industry include:
• Develop strategies for decarbonization to reduce emissions and ensure profitability
• Support policy development of clear objectives for investors
• Invest in promising projects, technologies, etc., that support achieving net zero
• Implement approaches to transition oil and gas products to low-carbon products like hydrogen (H2).
Oil and Gas Energy Transition Pathways
Pathways in the energy transition that the oil and gas industry is embarking on include:
1. Energy efficiency
2. Hydrogen system
3. Carbon capture, use, and storage (CCUS)
4. Low-carbon fuels
The energy efficiency lever can play a role in reducing emissions and enhancing energy in the power sector. Hydrocarbon facilities have a chance to utilize and convert oil and gas sources to hydrogen – a clean product – but must capture CO2 sources to achieve blue H2. The captured #CO2 sources from hydrocarbon facilities or the air can be collected in a hub to be directly used in the cement and concrete industries – just one potential opportunity to utilize captured CO2 – or stored directly underground with specific geological formations.
This article is contributed by Sonia Isabella López Kovács – Reservoir Engineer Advisor at Repsol.
Indonesia signed three oil and gas exploration and production contracts under the PSC scheme on September 21, 2023.
The three contracts are for the Akia work area, Beluga work area, and Bengara I work area. They were put up for tender by the Ministry of Energy and Mineral Resources during the first round of tender conducted in April 2023.
Here are the details of the three contracts.
AKIA WORK AREA
Location: Offshore North Kalimantan
Contractors: a consortium consisting of Armada Etan B.V. as the operator and Pexco Tarakan N.V.
Size of work area: 8394 Km2
Estimated reserves: 2 billion barrels of oil and 9 TCF of gas.
Signing bonus: 500,000 USD
Contractor’s commitments: Contractor to do 3 G&G studies, conduct 750 Km2 of seismic survey, and invest 7.7 million USD over the first three years upon signing.
BELUGA WORK AREA
Location: Offshore West Natuna
Contractor: Medco Energy Beluga
Estimated reserves: 360 million barrels of oil and 50 BCF of gas.
Signing bonus: 100,000 USD
Contractor’s commitments: Contractor to conduct 2 G&G studies, drill one exploration well, and invest 8 million USD in the first 3 years upon signing.
BENGARA I WORK AREA
Location: North Kalimantan
Contractor: TexCal Energy
Estimated reserves: 90 million barrels of oil equivalent (MMBOE)
Contractor’s commitments: Contractor to do 2 G&G studies, drill one exploration well, and invest 6.5 million USD in the first 3 years upon signing.
Signing bonus: 50,000 USD
In other news, the Ministry of Energy and Mineral Resources has put up three oil and gas work areas in Papua in its third round of tender in 2023. Indonesia is very keen to step up oil and gas exploration and production to boost its hydrocarbon production.
World’s first bulk liquefied hydogen carrier – Suiso Frontier
Suiso Frontier is the world’s first bulk liquefied hydrogen carrier in the world. The word “suiso” implies hydrogen in Japanese. Suiso Frontier is designed and manufactured by Kawasaki Heavy Industries and operated by Shell under the CO2-free Hydrogen Energy Supply-chain Technology Research Association (HySTRA) project funded by the Japanese government and various partners.
The vessel can carry up to 1,250 cubic meters of liquefied hydrogen at -253 degrees Celsius in the state-of-the-art storage tank.
The vessel completed its maiden voyage between Australia and Japan in February 2022. After it underwent refitting, the vessel is now in the next phase of the demonstration which aims to assess the performance, reliability, and integrity of the vessel’s system through more load-unload cycles and to gain more operational experience.
Here are several comments on Suiso Frontier and hydrogen as a clean fuel of the future. During the vessel’s visit to Singapore on September 3-9, 2023, Mr Teo Eng Dih, Chief Executive of the Maritime and Port Authority of Singapore (MPA) said, ” Singapore announced our National Hydrogen Strategy in late 2022. The properties of hydrogen, and its potential to be produced at scale using renewable sources, makes hydrogen a potential fuel to support the energy transition to a low and zero carbon future.”
“MPA is actively studying the use of hydrogen and its carriers as a marine fuel and welcomes the collaboration with industry players such as Kawasaki Heavy Industries and Shell, as well as our work with our research community such as the A*STAR Institute of High-Performance Computing, to bring the Suiso Frontier to Singapore. This vessel visit has helped to inform the development of safety and operational procedures, and also support further feasibility studies and preparations for the deep-sea transportation and receipt of liquefied alternative fuels.”
Mr. Shigeru Yamamoto, Executive Officer, of Hydrogen Strategy Division of Kawasaki Heavy Industries said, “We strongly believe that an international supply chain of liquefied hydrogen by marine transportation is essential to realize a carbon-neutral world. The world’s first liquefied hydrogen carrier, Suiso Frontier, showed the world that cryogenic liquefied hydrogen can be transported by ship. We are confident that liquefied hydrogen will attract even more attention from around the world in the future.”
Mr. Nick Potter, General Manager of Shell Shipping and Maritime for Asia Pacific and the Middle East, said, “Transportation through deep-sea shipping is one of the critical steps essential for unlocking the use of hydrogen as a future zero-carbon fuel. The Suiso Frontier represents a key milestone in demonstrating the technical feasibility of liquefied hydrogen shipping and Shell’s maritime leadership in this area. Shell also remains committed to the safe and efficient operations of the vessel.”
This article is adapted from the content published by the Maritime and Port Authority of Singapore (MPA).
Some hot and permeable liquid-dominated geothermal wells do not naturally self-discharge their reservoir fluid after they are drilled or shut in for some time. Non-self-discharge wells are common in conventional liquid-dominated geothermal fields.
Here are several reasons why some geothermal wells are unable to flow:
Low reservoir pressure.
Formation damage caused by drilling.
Build up of water column in the well after a long shut in period.
The long water column in the well after drilling or workover.
Poor reservoir permeability.
High-elevation terrain.
Small production casing.
After a geothermal well is drilled and completed, as a standard practice, it will be tested to determine its potential.
Before it is tested, engineers will assess whether the well will flow. For new wells, the two common analysis methods used are the Af/Ac ratio method and the water column length method.
A well is considered a non-self-discharge when the ratio of Af/Ac is less than 0.7, while a well with an Af/Ac ratio of more than 0.85 has an excellent chance to self-discharge.
Based on a study of geothermal wells with more than 200 degrees C in Indonesia, a well is likely capable to self-discharge when the length of the water column in the well is less than 600 meters, whereas if it is more than 600 m, the well may not self-discharge. The water column length is the vertical distance between the water level in the well and the depth of the feed zone.
How do you stimulate a non-self-discharge geothermal well to make it flow?
Once it is established or predicted that the newly drilled geothermal well will not or is unlikely to self-discharge, engineers will apply a stimulation technique to make the well flow.
When the well reservoir pressure is not sufficient to lift the column of water that has accumulated in the well, a well discharge stimulation technique will be applied to jump-start the well. There are five stimulation techniques to discharge the water. They are:
Air compression
Well-to-well stimulation
Nitrogen injection
Air injection
Injection of steam from a portable boiler.
If a well is unable to flow due to formation damage or low permeability, other stimulation techniques such as fracturing or acidizing may be considered.
Air Compression Stimulation Technique
Air compression stimulation is the simplest and cheapest method with a proven high success rate compared with other methods. This method does not need complicated facilities, mobilization, or installation.
One disadvantage of this method is the well casing may crack due to sudden thermal shock from the flow of hot fluids during well discharge. It should be considered with caution for wells with temperatures above 300 °C.
In this technique, an air compressor is connected to one of the wellhead side valves to inject pressurized air into the well to depress the water level and push all the cold water from the wellbore into the hot formation. This will make the hydrostatic pressure of the water column lower than the reservoir pressure. After pushing the water level below the casing shoe and allowing enough time for the cold water to heat up by the hot reservoir rock, the wellhead valve is opened quickly to create a sudden effect of buoyancy.
Here is an example of a successful application of the air compression method to stimulate a geothermal well.
Well A Case
The company wanted to test Well A. The Af/Ac ratio method was used to predict whether Well A would self-discharge. The initial Af/Ac ratio of Well A is zero and thus it was categorized as a non-self-discharge well. To stimulate the well, the air compression method was chosen.
To stimulate the well, engineers injected air into the well at a pressure of 50 Bars using a double booster compressor for 24 hours. The compressed air pushed down the water level inside the well by 500 m resulting in a final Af/Ac ratio of 2.371.
The application was successful as the well flowed by itself when the well was reopened.
Acknowledgment
This article is adapted based on the following sources:
Post by Dr. Mohamad Husni Mubarok on LinkedIn – Determining the minimum air compression pressure to stimulate the non-self-discharge geothermal well.
“Stimulation program of air compression and nitrogen injection in geothermal well” by E. Budirianto, W.A. Nugroho, B.N. Jayanto, A.H. Lukmana, D.R. Ratnaningsih
Article by Mohamad Husni Mubarok and Sadiq J. Zarrouk – Discharge Stimulation of Geothermal Wells: Overview and Analysis.
The first offshore oil platform decommissioning in Indonesia was completed in November 2022. The decommissioning of the EB platform of the giant Attaka oil field was carried out by Pertamina Hulu Kalimantan Timur as the field operator and KHAN Co. Ltd. of South Korea.
This platform decommissioning is called the Attaka Rig to Reef Project aimed to promote an effective and environmentally friendly approach to protect the ecosystem and develop future ecotourism. In the project, the platform was removed and put in a conservation area.
As many offshore oil and gas fields in Indonesia were discovered in the late 1960s and early 1970s, many of their platforms are nearing the end of their productive life, such as the ones in the Offshore North West Java block and the West Seno field according to SKK Migas.
The prolific Attaka field was discovered by Unocal along with its partner, INPEX, in 1970 in the East Kalimantan offshore working area. The Attaka field is the first commercial offshore oil field in Kalimantan. At its peak, it produced 110,000 barrels of oil and 150 MMSCF of gas per day. After more than 50 years of production, its daily oil production today has declined to less than 5000 BOPD.
Pertamina Hulu Kalimantan Timur became the field operator in October 2018.
The Gagak Rimang FSO operated by ExxonMobil Indonesia.
The two top oil operators in Indonesia account for more than 50% of the total crude oil production in Indonesia in 2023. They are Pertamina Hulu Rokan and ExxonMobil Cepu Limited.
PERTAMINA HULU ROKAN
Pertamina Hulu Rokan, the operator of the massive Rokan block, is the current largest oil producer in Indonesia.
Oil production from the Rokan block has been increasing through its ongoing massive development well drilling program since PHR acquired the block from Chevron in August 2021.
The oil production from the Rokan block went above 172,000 BOPD recently. This is the highest daily production since the acquisition.
PHR has drilled 825 development wells in the Rokan block. While the massive development drilling is continuing, PHR has started drilling the first well to explore the unconventional hydrocarbon in the Rokan block.
EXXONMOBIL CEPU LIMITED
ExxonMobil as the operator of the prolific Banyu Urip oil field in East Java produces 164,000 BOPD from the field.
EMCL was the biggest oil producer in Indonesia at one time, producing more than 200,000 BOPD during its peak. However, producing since 2008, oil production from the Banyu Urip field is declining.
To boost its production, ExxonMobil will drill five infill wells targeting the carbonate formation and two infill wells targeting the clastic formation in 2024.
This seven-well drilling of the field optimization program is expected to increase oil production by 18,000 BOPD and add 42 million barrels of oil reserve.
EMCL has contracted PDSI (Pertamina Drilling Services Indonesia) to drill the seven wells in 2024.
Currently, LNG production in Indonesia comes from three LNG plants: The Badak LNG, the Tangguh LNG, and the small 2 MTPA Donggi-Senoro LNG plant.
In the last five years, Indonesia’s LNG production volume declined by 23%, from 18.2 MTPA in 2018 to 14 MTPA in 2022 due to the declining production from the Badak LNG plant.
The Badak LNG plant, one of the largest LNG plants in the world has been in operation for 45 years since it began production in 1977 in East Kalimantan.
The Badak LNG plant comprising eight trains has a total production capacity of 22.6 MTPA. However, due to the declining gas supplies from its surrounding oil and gas fields in East Kalimantan, only two trains are now in operation.
Due to the issue of dwindling gas supplies, most of the LNG from the Badak plant is sold as short-term or spot cargoes in 2022 as it cannot secure medium and long-term deals.
The Tangguh plant is carrying the heavy load of producing the LNG for the export market. Started producing LNG in 2009, the Tangguh plant currently consists of two trains with a total production capacity of 7.6 MTPA.
Most of Indonesia’s LNG cargoes are sold in the Asia Pacific region as expected. However, thanks to the recent high LNG spot prices, some cargoes also reached European markets.
For the domestic LNG market in 2022, the “real” LNG consumption has reached 3.17 MTPA, about 23% of annual production. This number is, unfortunately, lower than the annual LNG volume consumed by some neighboring countries like Thailand (8.2 MTPA), Singapore (3.7 MTPA), and Bangladesh (4.4 MTPA).
Good progress is coming from the performance of Perta Arun Gas, which is operating the Arun LNG Regas Terminal and LNG Hub in Aceh. So far, almost one metric ton of LNG volume has been unloaded into Arun LNG tanks and later reloaded for final delivery.
FUTURE
In the future, the Tangguh and the future Masela plants will play a key role in positioning Indonesia as one of the top LNG producers with a total plant capacity of 33 MTPA.
The Tangguh Train #3 which is set to go on stream by the end of 2023 will increase the total Tangguh LNG plant capacity by 3.8 MTPA to 11.4 MTPA.
With the divestment of Shell’s interest in the Masela block, the Abadi LNG plant with a capacity of 9.5 million tons per year is expected to be completed by 2030.
Currently, up to 17 MTPA of future volume is still uncontracted. However, according to SKK Migas, there are huge interests in Indonesia’s LNG.
Fishing operation recovering a 12 1/4-inch directional drilling BHA.
Situations, where fishing is necessary, can arise during oil and gas well drilling or workover operations.
Fishing situations occur when equipment is stuck or lost in the hole. They are quite common in oil and gas well drilling or workovers. It happens to one in five wells.
While some fishing operations are simple, some of them can be very difficult or even impossible.
When fishing is impossible or deemed too difficult, the operator can opt to either redrill a new well or to sidetrack by opening a new track in the existing hole to bypass the fish.
Here are the two commonly asked questions when an operator is in a fishing situation.
Should we fish or not?
How much time should we spend to recover the fish?
Many fishing jobs are difficult and require special tools and the expertise of a fishing specialist. However, even with the best tools (which may have a high daily cost) and procedures, sometimes the fishing attempt fails or takes a long time.
It is vital to know everything possible about the fish and fishing conditions before starting the job so you can ascertain the level of difficulty. The operator should consider some fishing jobs impractical from the very start. For example, drill collars accidentally cemented in or engulfed in barite are nearly impossible to recover and are not worth the cost, even if they are recovered. In these situations, you should not proceed with fishing and should begin side-tracking instead.
When it is difficult to decide what is fishable and you do not know the probability of success, it is best to estimate the cost of side-tracking and determine how long to fish.
The cost of side-tracking can be estimated easily. It takes about 5 days to set a cement plug on top of a fish and kick off the hole to bypass the fish.
You can estimate the cost of drilling a new hole to reach the original total depth if you know the:
rate of penetration
length of the original hole.
It is also important to recognize when it is time to stop fishing and start re-drilling. You need to determine how long to fish so that the cost of the fishing operations and lost drilling time do not exceed the cost of side-tracking.
Generally, you should stop fishing and decide to sidetrack the well when the cost of fishing has reached about half the cost of side-tracking.
The following equation calculates the number of days that should be allowed for fishing.
D = (V + CS)/(R + CD)
where:
D = Number of days to be allowed for fishing
V = Replacement value of the fish
CS = Estimated cost of side-tracking
R = Daily cost of fishing tool rental and services
CD = Daily rig operating cost.
After you calculate the maximum number of days to spend fishing, you may realize that it will take longer than the allotted time to fish. In this case, it would be better off to side-track instead of attempting to fish.
This article is written by Rick Patenaude. Rick started his oilfield career in the Powder River Basin of Wyoming in the mid-1980s. He joined Weatherford as a Fishing Tool Supervisor in 1995 and worked throughout the Rocky Mountain Region until 2003. Rick transferred to China in 2003 to support Weatherford’s operations in the Pearl River Basin and Bohai Bay until 2006. Rick was then transferred to Jakarta to support the growing well-intervention market for both national and international clients. In 2012 Rick was assigned to Balikpapan as Project Manager Fishing & Re-Entry Services for Chevron’s West Seno Extended Reach Drilling Project. Upon completion of the West Seno Project Rick returned to Jakarta and began supporting operations throughout the Asia Pacific Region including New Zealand, Australia, India, Brunei, Malaysia & Japan.
The photo above shows the fish recovered with a skirted screw-in sub after a successful wash-over operation to burn off the blades on the integral bladed stabilizer. The fish is a 12-1/4″ OD directional drilling BHA.
El Salvador is one of the few countries in the world which has a high percentage of electricity produced from geothermal resources.
Its two geothermal power plants, the 95 MW Ahuachapan, and the 109 MW Berlin plants with a combined installed capacity of 204 MW, supply 21.7% of the electricity needed in the country.
The journey of geothermal development in El Salvador began with exploration in 1955 for its geothermal potential, followed by the drilling of its first geothermal well in 1968.
The country’s first 30 MW Unit 1 Ahuachapán geothermal power plant was subsequently completed in 1975.
Two more power stations were later added – 30 MW Unit 2 in 1976 and 35 MW Unit 3 in 1981 – giving the Ahuachapán power plant a total installed capacity of 95 MW.
Ahuachapán’s three power stations are supported by 21 steam production wells and 9 reinjection wells.
Following the success of the Ahuachapan plant, LaGeo, the operator began building a second plant, the Berlin geothermal plant in 1992.
The Berlin plant consisting of four power stations with a total installed capacity of 109 MW is supported by 16 steam production wells and 23 reinjection wells.
El Salvador can easily double its electricity production from geothermal resources as it still has more potential to develop. It has an estimated 600 MW of untapped geothermal resources in the following areas:
Indonesia produces around 5.3 billion SCF of gas daily. Around 68% of its produced gas is sold to domestic users in the form of pipeline gas and LNG.
Currently, around 30% of its produced LNG is sold to domestic users and the rest is exported.
Indonesia wants to increase the use of LNG to provide the gas needed for domestic use. However, the current prices of LNG for the domestic market are considered too high by consumers as they are around $6 per MMBTU higher than the gas delivered via pipeline. The current oil indexation pricing of LNG is also considered unfavorable to consumers as the prices can escalate drastically.
What should be the price of Indonesia’s LNG for domestic sales?
This article provides a thorough analysis of the current gas and LNG prices for sales in Indonesia including the pricing policy, and a suggestion for reducing the price gap between LNG and pipeline gas.
CURRENT PRICES OF GAS AND LNG IN INDONESIA
Figure 1 – LNG and gas prices in Indonesia
Currently, there are big gaps between LNG prices and the downstream gas prices paid by gas consumers in Indonesia. As the country wants to increase the use of LNG to support the gas market, it should find a pricing mechanism to reduce those gaps. Otherwise, all LNG, either from domestic or international sources, will find it hard to find buyers in the Indonesian gas market.
The LNG costs shown in the graph are the landed prices at the receiving terminal plus applicable import duties/taxes of around 17% and regasification costs of around $2.5 per MMBtu. Downstream pipeline transportation fees are note included here.
The downstream gas market in Indonesia has several gas price layers:
Prices of gas fixed by the government for Household and Prioritized Industries – $5-6 per MMBTU.
Gas Market served via downstream pipelines by PGN (Perusahaan Gas Negara) – $6-9 per MMBTU.
Gas from LNG supplied by Nusantara Regas FSRU to PLN power plants in Muara Karang and Tanjung Priok – $9-12 per MMBTU.
LNG PRICES FROM 2017 – 2027
Figure 2 – LNG and gas prices from 2017 – 2027
Figure 2 shows how LNG prices moving along the Indonesian gas prices and their price spread from 2017 to 2027. The period includes the event of Covid-19 when oil prices dropped below $50 per barrel and the Russia-Ukraine conflict when oil prices climbed above $80 per barrel.
As the graph shows big swings in the price spread between domestic LNG and gas due to international events. It reached $10 per MMBTU during the onset of the Russia-Ukraine conflict.
The graph also shows the domestic LNG supply is still the cheapest option for Indonesia while US LNG could bring better prices at times.
A NEW LNG PRICING MECHANISM FOR DOMESTIC USAGE
Figure 3 – LNG cost-pass-through illustration
It will be difficult for LNG to play a big role in supporting the growth of Indonesia’s gas market with the current LNG pricing scheme. As the need for gas will continue to grow, with all existing regasification terminals in Jakarta, Lampung, and Arun as well as future additions, the gas market can double in size if the LNG price is priced correctly.
So, is there a way to change or adjust the LNG pricing mechanism for domestic sales, and at the same time keep sufficient return on investment for all involved parties?
Is it possible to reduce the net cost of gas derived from LNG to consumers to around $6-9 per MMBTU, the price that is within the paying capability of domestic users?
Cost-Pass-Through LNG Pricing
One solution is to apply the concept of a “cost-pass-through pricing mechanism” instead of oil indexation.
To illustrate this concept, the Badak LNG plant in Bontang is used as a study case.
The Badak plant is chosen for discussion because it is fully depreciated as it has been in operation since 1978, and due to its strategic location, it easily covers the entire part of Indonesia within 2,000 nautical miles.
The followings are best-estimate cost component figures used to calculate the Cost-Pass-Through price of LNG for long term or medium-term domestic sales and purchases. All these numbers meet the required project returns of each party.
Upstream gas cost in the form of a fixed number with an escalation factor subjected to governmental approval. For the case of Badak LNG, as there is no more cheap gas available, the upstream gas is assumed at a fixed cost of USD 4.5/MMBTU
LNG production cost, covering the operations & maintenance cost is fixed at USD 0.50/MMBTU
Shipping cost, a fixed cost of USD 0.5/MMBTU based on a fixed Time Charter Rate for long term or medium-term contracts.
Trading margin at USD 0.40/MMBTU
Regasification cost, averaging a fixed cost of USD 2.5/MMBTU among existing regassification terminals.
Based on these figures, the total cost of gas derived from LNG applying the cost-pass-through concept is around $8.4 per MMBTU. This is within the price range of $6-9 per MMBTU.
In conclusion, unlike the existing oil-indexed LNG pricing formula for domestic sales, in this “cost-plus-through” scheme all cost components in the LNG pricing are fixed numbers. This is good and fair for Indonesian gas consumers because the supply is sourced within the country and the costs are not affected by any geopolitical risks and fluctuation of international energy references like oil prices.
When the gas derived from LNG produced from big plants like the Badak plant could be delivered below the USD 9/MMBTU level, it will certainly boost the demand for gas in Indonesia especially in its remote areas.
Sun rising at Mahakam River. Photo courtesy of Rick Patenaude
With many big, depleted oil and gas reservoirs, Indonesia has a huge capacity and the potential to become a regional hub for storing CO2. It has an estimated capacity to store more than 400 gigatons of CO2.
Developing facilities for storing captured CO2 is not just a way to reduce the amount of CO2 released into the atmosphere, it can also generate revenues of around $50 per ton of CO2 stored.
As the first step, Pertamina is working with ExxonMobil to study the CCS feasibility of its depleted reservoirs in the Sunda-Asri basin. Pertamina and ExxonMobil will come up with a commercial model design for the regional CCS hub development in the working area of PT Pertamina Hulu Energi OSES.
Here are the assets and areas that the Ministry of Energy and Mineral Resources has identified as having the potential for carbon storage, carbon capture, or carbon utilization.
Carbon Storage (CS) • Arun reservoir
Carbon Capture, Utilization and Storage (CCUS) with EOR • Gemah field • Ramba field • Sukowati field • Tangguh field • Jatibarang field
Carbon Capture and Storage (CCS) • Abadi field • Sakakemang field
CCS/CCUS Hub • Central Sumatra Basin • Kutai basin • Sunda Asri basin • East Kalimantan
Here is an update on CCU-CCUS projects in Indonesia announced during the 14th Clean Energy Ministerial meeting hosted by India, on 19-22 July 2023 in Goa.
Approved Plan CCUS Project BP Berau project – Ubadari Field Development, and Vorwata EGR/CCUS and onshore compression. Increase gas production and reduce CO2 emissions by up to 33 MT by 2045.
Potential Future CCU-CCUS projects ▪ PT Pertamina EP Gundih CCUS-EGR Project. Potentially reduce 3 MT of CO2 for 10 years. ▪ PT Pertamina EP Sukowati CCUS-EOR Project. Potentially reduce CO2 10 MT for 15 years. ▪ Repsol Sakakemang CCS Project. ▪ Abadi CCS Project. Reducing native CO2 2.8 MTPA or 70MT for 25 years. ( Inpex, Pertamina and Petronas) ▪ Blue Ammonia + CCS in Central Sulawesi (Pertamina, PT PAU, JOGMEC, Mitsubishi & ITB), Potential CO2 reduction around 19 MT for 20 years. ▪ Arun CCS (Joint venture of Carbon Aceh & PEMA). ▪ Ramba CCUS (Pertamina). ▪ Central Sumatera Basin CCS/CCUS Hubs (Pertamina & Mitsui). ▪ Asri Basin CCS Hubs (Pertamina & ExxonMobil). ▪ East Kalimantan CCS/CCUS Study (Pertamina & Chevron). ▪ East Kalimantan CCS/CCUS Study (Kaltim Parna Industri & ITB), surface facility study. ▪ CCU to Methanol – Pertamina Refinery Unit V (Pertamina & Air Liquide) ▪ Gemah field CCUS CO2-EOR. ▪ Jatibarang CCUS CO2-EOR (Pertamina & JOGMEC). Ongoing field trial.
The first offshore oil platform decommissioning in Indonesia was completed in November 2022. The decommissioning of the EB platform of the giant Attaka oil field was carried out by Pertamina Hulu Kalimantan Timur as the field operator and KHAN Co. Ltd. of South Korea.
This platform decommissioning is called the Attaka Rig to Reef Project aimed to promote an effective and environmentally friendly approach to protect the ecosystem and develop future ecotourism. In the project, the platform was removed and put in a conservation area.
As many offshore oil and gas fields in Indonesia were discovered in the late 1960s and early 1970s, many of their platforms are nearing the end of their productive life, such as the ones in the Offshore North West Java block and the West Seno field according to SKK Migas.
The prolific Attaka field was discovered by Unocal along with its partner, INPEX, in 1970 in the East Kalimantan offshore working area. The Attaka field is the first commercial offshore oil field in Kalimantan. At its peak, it produced 110,000 barrels of oil and 150 MMSCF of gas per day. After more than 50 years of production, its daily oil production today has declined to less than 5000 BOPD.
Pertamina Hulu Kalimantan Timur became the field operator in October 2018.
Producing around 5.3 billion SCF of gas daily in 2022, Indonesia utilized domestically 68% of its produced gas. The surplus was exported in the form of LNG and pipeline gas.
Here is the breakdown of the utilization of the produced gas.
Domestic Industrial use – 29%
LNG for export – 22%
LNG for domestic use – 9%
Fertilizers – 12.5%
Electricity generation – 11.5%
Exported Pipeline gas – 11%
LPG – 1.5%
The domestic need for gas is expected to grow in the form of gas and LNG as gas pipelines and FSRUs (floating storage and regasification unit) is being built.
Despite this, Indonesia will continue to have a surplus of gas in the coming years as the Tangguh LNG train #3 will go on stream by the end of 2023 and the Abadi LNG plant will be operating by the end of 2030, according to Rizal Fajar Muttaquien of SKK Migas.
PT Pertamina, the national oil company of Indonesia, is an integrated oil company and much more.
It is the largest oil and gas producer in Indonesia. Operating 27000 oil and gas wells in 65 oil and gas blocks and producing 566,000 barrels of oil and 2600 MMSCF of gas daily in 2022, Pertamina produces 68% and 34% of the total crude oil and natural gas respectively in Indonesia. Its total daily hydrocarbon production is equivalent to 967,000 BOEPD.
HISTORY OF PERTAMINA
Pertamina began as Perusahaan Minyak Nasional (Permina) on December 10, 1957. The 10 December 1957 date is celebrated as the birthdate of Pertamina.
In 1960 Permina became Perusahaan Negara Permina (PN Permina). It then acquired and managed all the oil and gas assets of BPM (Bataafsche Petroleum Maatschappij) in 1965.
PN Permina became PN Pertamina (Perusahaan Negara Pertambangan Minyak dan Gas Bumi Negara) on 20 August 1968.
Finally, PN Pertamina became PT Pertamina, a limited company as it is today on 18 June 2003.
From the late 1960s through the 1990s Pertamina was in charge of all the production-sharing contracts issued to foreign oil companies.
Pertamina, with the status of PSO (Public Service Obligation) given in 1972, has the mandate to supply and distribute all the fuels needed in Indonesia.
COMPANY STRUCTURE
Currently, Pertamina conducts its operations under six sub-holding companies: • PT Pertamina Hulu Energi – Upstream oil and gas operation • PT Perusahaan Gas Negara – Gas supply and distribution • PT Kilang Pertamina International – Oil refining and petrochemicals • PT Pertamina Power Indonesia – Power generation and Renewable energy • PT Patra Niaga – Commercial and Trading • PT Pertamina International Shipping – Oil and gas shipping and marine logistics
PRESIDENTS OF PERTAMINA
Ibnu Sutowo is the first and the most notable president of Pertamina. During his tenure from 1968-1976, he oversaw all the PSC contracts signed by many international oil companies that created the oil boom in Indonesia from 1970-2000. He was given full authority by the then-president of Indonesia, Soeharto, to develop the oil and gas resources of Indonesia.
Here are the past and the current presidents of Pertamina.
Ibnu Sutowo (1968-1976).
Piet Haryono (1976-1981).
Joedo Soembono (1981-1984).
R. Ramli (1984-1988).
Faisal Abda’oe (1988-1996).
Soegijanto (1996-1998).
Martiono Hadianto (1998-2000).
Baihaki Hakim (2000-2003).
Ariffi Nawawi (2003-2004).
Widya Purnama (2004-2006).
Ari Soemarno (2006-2009).
Karen Agustiawan (2009-2014).
Dwi Soetjipto (2014-2017).
Elia Massa Manik (2017- 2018).
Nicke Widyawati (2018 – now).
Board of Directors and Executive Team
Here are the newly elected board of directors and the executive team of Pertamina announced during the annual general meeting of shareholders on July 25, 2023.
Board of Directors
Chairman – Basuki Tjahaja Purnama
Vice Chairman – Rosan P. Roeslani
Board member – Heru Pambudi
Board member – Rida Mulyana
Independent board member – Alexander Lay
Independent board member – Ahmad Fikri Assegaf
Independent board member – Iggi H. Achsien
Executive Team
President and CEO – Nicke Widyawati
Chief of Logistics and Infrastructure – Alfian Nasution
Chief of Finance – Emma Sri Martini
Chief of Human Resources – M. Erry Sugiharto
Chief of Business Support – Erry Widiastono
Chief of Portfolio Strategy and Business Developmenet – Atep Salyadi Dariah Saputra
This post is adapted by Jamin Djuang – Chief Learning Officer of LDI Training
The Kamojang Power Station of Pertamina Geothermal Energy – Photo courtesy of PGE.
The Beginning
Indonesia is the second-largest geothermal energy producer in the world, after the US, with a total installed capacity of 2356 MW as of January 2023 according to ThinkGeoEnergy.
The story of geothermal in Indonesia began in 1918 when Dutchman JB Van Dijk noticed and reported the geothermal potential in the Kamojang area in West Java.
Inspired by the successful geothermal development in Larderello in Italy, a Dutch company drilled five shallow wells between 60 to 128 meters deep from 1926 to 1927 in the Kamojang area. One of them, the well KMJ-3, was successful and is still producing steam today.
This discovery established the Kamojang area as having tremendous potential for geothermal energy development.
Subsequently, in 1974 Pertamina began exploring and assessing the geothermal resources in Kamojang in earnest with the cooperation of New Zealand.
Then in 1978, the first geothermal power station in Indonesia came into production at Kamojang with an installed capacity of 0.25 MW.
Today the Kamojang power plant consists of 5 power stations with a total installed capacity of 235 MW making it one of the biggest geothermal power plants in Indonesia.
Since the establishment of the Kamojang plant, many companies started to develop geothermal resources in Java, Sumatra, and the Eastern part of Indonesia.
Here are the seven geothermal operators in Indonesia.
PERTAMINA GEOTHERMAL ENERGY
Pertamina Geothermal Energy is the first and the most active geothermal company in Indonesia. It constructed the first geothermal plant in Indonesia, the Kamojang power plant in 1978 with the cooperation of New Zealand.
PGE operates and supplies steam to 21 geothermal power plants in six work areas, namely in Kamojang, Sibayak North Sumatra, Ulubelu, Lahendong, Lumut Balai South Sumatra, and Karaha West Java. The total installed capacity of the 21 power stations is 672 MW.
Besides these direct operations, PGE has joint operation contracts with several geothermal operators in the operations of their power plants with a total of 1205 MW installed capacity.
Pertamina Geothermal Energy became a public company on February 24, 2023. With the 594 million USD of fresh funds it received from the IPO, PGE plans to add 600 MW of installed capacity by 2027, according to its CEO Mr. Ahmad Yuniarto.
Here are the geothermal plants which PGE operates: • 235 MW Kamojang Unit 1, 2, 3, 4, 5 in West Java (Note: Supplying steam to Units 1, 2, and 3 operated by PLN) • 120 MW Lahendong Unit 1, 2, 3, 4, 5, 6 in Sulawesi • .5 MW Lahendong Binary in Sulawesi • 110 MW Ulubelu Unit 1 and 2 in Lampung Sumatra (Note: Supplying steam to PLN) • 110 MW Ulubelu Unit 3 and 4 in Lampung Sumatra • 55 MW Lumut Balai Unit 1 in South Sumatra • 30 MW Karaha Bodas in West Java • 12 MW Sibayak Unit 1 ,2 and 3 in North Sumatra
Current Projects • Constructing 55 MW Lumut Balai Unit 2 power station. • Enhancing electricity generation capacity by applying binary technology in Hululais, Lumut Balai, Ulubelu, and Lahendong plants. • Planning to build two 55 MW power stations in the Hululais work area in Bengkulu, Sumatra.
STAR ENERGY GEOTHERMAL
Star Energy Geothermal was established in 2003. Its vision is to be the fastest-growing, most profitable, best-managed energy company in the region.
Star Energy, operating three geothermal power plants with a total installed capacity of 874 MW, is the largest geothermal energy producer in Indonesia.
Here are the three geothermal plants that it operates. • Salak plant (337 MW) in West Java – Acquired from Chevron in 2017 • Darajat plant (270 MW) in West Java – Acquired from Chevron in 2017 • Wayang Windu (227 MW) in West Java – Acquired from Magma Nusantara Limited in 2004
Current Projects • Exploring the geothermal prospect in Gunung Hamiding, located in North Maluku. • Exploration in Sekincau in Lampung, Sumatera
Here are the subsidiary companies of Star Energy Geothermal: • Star Energy Geothermal Salak, Ltd. • Star Energy Geothermal (Wayang Windu) Limited| • Star Energy Geothermal Darajat II, Limited • PT Star Energy Geothermal Suoh Sekincau
PT GEO DIPA ENERGY
Geo Dipa Energy was established in 2002 by the government of Indonesia to build and operate the Dieng and Patuha geothermal plants.
Managing two geothermal plants with a combined capacity of 125 MW, Geo Dipa Energy’s vision is to be a reliable and trusted geothermal company.
Here are the two plants that Geo Dipa Energy operates: • 70 MW Dieng Unit 1 power plant located in Central Java. • 55 MW Patuha Unit 1 power plant located in West Java.
Current Projects • Dieng Unit 2 Development. Geodipa is currently drilling steam wells for the 55 MW Dieng Unit 2 power station project. • Patuha 55 MW Unit 2 Development. • Exploration in the Candradimuka work area. • Exploration in the Arjuno Welirang work area.
KS ORKA RENEWABLES PTE LTD
KS Orka Renewables, established in 2015, manages and operates four geothermal stations in North Sumatera and Flores.
Here are the power plants which KS Orka Renewables operates: • 140 MW Sorik Marapi Unit 1, 2, and 3 power stations in North Sumatera • 5 MW Sokoria geothermal plants in Flores.
Current Projects: • Development of 50 MW Sorik Marapi Unit 4 station • Exploration in the Samosir work area in North Sumatera
Here are the operating subsidiary companies of KS Orka Renewables:
PT Sorik Marapi Geothermal Power
PT Sokoria Geothermal Indonesia
PT Samosir Geothermal Power
PT SUPREME ENERGY
Supreme Energy was established in 2007 with a vision to become the leading and the most respected geothermal, generating clean and sustainable electricity.
Supreme Energy operates three power stations in two work areas with a total installed capacity of 130 MW.
Here are the three power stations: • The 45.6 MW Unit 1 and 45.6 MW Unit 2 stations in the Rantau Dedap work area in South Sumatera. • The 85 MW Muara Laboh Unit 1 power plant in West Sumatera.
Current Projects • Exploration in the Rajabasa work area • Development of 75 MW Muara Laboh Unit 2 power station.
Here are the three subsidiary companies of Supreme Energy:
PT Supreme Energy Rantau Dedap
PT Supreme Energy Muara Laboh
PT Supreme Energy Rajabasa
SARULLA OPERATIONS LIMITED
Sarulla Operations Limited is a consortium consisting of Medco Power Indonesia, INPEX, Ormat Technologies, Itochu Corporation, and Kyushu Electric Power.
Sarulla Operations Limited was established in 2006 when PLN, the national power company of Indonesia, awarded the company to take over the development of the Sarulla geothermal project in North Sumatra.
The Sarulla geothermal resources, located in North Sumatra, were initially discovered by Unocal. Unocal conducted extensive exploration in the Sarulla geothermal working area from 1993 to 1998. It drilled a total of 13 deep wells and proved the existence of 330 MW of commercial geothermal reserves for 30 years.
However, due to the Asian financial crisis in 1997, Unocal did not get the approval to build the power plants.
With a total investment of 1.7 billion USD, Sarulla Operation Limited completed the first power station in March 2017, the second station in October 2017, and the third station in March 2018.
Here are the three power stations that SOL operates: • 110 MW Silangkitang (SIL) Unit 1 • 110 MW Namora-I-Langit (NIL) Unit 1 • 110 MW Namora-I-Langit (NIL) Unit 2
PLN GAS AND GEOTHERMAL
PLN Gas and Geothermal is a subsidiary company of Perusahaan Listrik Negara (PLN), the national power company of Indonesia.
As the sole distributor of electricity in Indonesia, besides purchasing electricity from all independent geothermal operators, PLN also operates several geothermal power plants of its own.
Here are the geothermal plants which PLN operates: • 110 MW Ulubelu Unit 1 and Unit 2 – Steam supplied by Pertamina Geothermal Energy • Kamojang Unit 1 (30 MW), Unit 2 (55 MW), and Unit 3 (55 MW) – Steam supplied by Pertamina Geothermal Energy • 10 MW Ulumbu Unit 1,2,3,4 in Flores • 2.5 MW Mataloko in Flores
PLNGG has an ambitious plan to produce more geothermal power from its geothermal work areas. It is working to add 10 MW capacity in its Ulumbu work area.
It is also currently looking for international and national investors to partner and collaborate to develop the following four geothermal projects: • 20 MW Tulehu in Central Maluku • 10 MW Atadel in East Nusa Tenggara • 10 MW Songa Wayaua in North Maluku • 20 MW Tangkuban Perahu in West Java
Epilogue As Indonesia is eager to increase its electricity generation using renewable resources, and with its abundant geothermal resources in its backyard, we shall see more geothermal development in the future.
Jamin Djuang – Chief Learning Officer of LDI Training
